Gas Hydrates-Not So Unconventional

For years, gas hydrates have been a resource that produced enormous in-

place volume estimates. The U.S. Geological Survey (USGS) estimated as

much as 16.7Tm³ (590Tcf; 106Bboe) in-place on the North Slope of Alaska

in 1995 that covers an area of about 145,000 km² (equivalent to

approximately 25 North Sea quadrants). World wide estimates also

focused on in-place gas volumes because, at that time, there was not any

methodology to assess what actually could be produced from these

deposits.  

Since these first published reports, a number of tests, experiments, and

much research has been conducted on gas hydrates, allowing

assessments to focus on the technically recoverable resources for the first

time.  

"Test results from the Mallik well and other research have pointed the way

to treating gas hydrate in a much more conventional manner," say Dr.

Timothy Collett, a leading gas hydrate researcher for the USGS. "Our

recently releasedAssessment of Gas Hydrates on the North Slope,

Alaska, 2008, is based on the same geologic elements to define a Total

Petroleum System (TPS) we use to assess conventional plays. We were

able, for the first time, to obtain the undiscovered, technically recoverable

volume of gas from hydrates for an area, in this case, northern Alaska. To

this end, these resources can be discovered, developed, and produced by

using current oil and gas technology."

Naturally occurring - huge volumes

The USGS estimates

about 2.4Tm³ (85Tcf; 15Bboe) of undiscovered, technically recoverable gas resources within gas

hydrates in Alaska. The area is mostly Federal, State, and Native lands covering 145,000 km² (the

equivalent of some 25 North Sea quadrants). ©USGSA gas hydrate is similar to ice, a

crystalline solid, where the gas molecule is surrounded by a cage of water

molecules. Many gases are suitable to form hydrates, however methane is

by far the most commonly found in marine and polar occurrences.  

Experimenting with mixtures of chlorine and water, Humphrey Davy and

Michael Faraday may have been the first to discover hydrates. The 1823

paper from the Transactions of the Royal Society of London, by Faraday,

discusses experiments with the chlorine hydrate. Because a hydrate had

never been seen in nature, they remained an academic curiosity through

the 19th century. When hydrates were found to be forming in the gas

pipelines in the mid-1930s, the North American gas industry focused on

ways to predict and inhibit hydrate formation. In 1970, Soviet researchers

registered the possibility that gas hydrates could exist in large volumes in

the earth's crust, and, in 1972, naturally occurring gas hydrates were

eventually recovered from the Black Sea.  

Since that discovery, marine hydrate-containing sediments covering huge

areas of the sea floor have been found in deep-sea drilling and coring in

more than 50 regions of the world's oceans and even in some large lakes

(Baykal in Russia is one). Hydrates are stable in marine sediments below

about 500 meters in water depth and stable in association with permafrost

in Polar Regions in both onshore and offshore sediments.  

Gas is greatly concentrated in hydrates where a unit volume of methane

hydrate can produce about 160 unit volumes of gas at one atmosphere.

Worldwide, the methane contained (in-place volumes) in gas hydrates is

about twice the amount of carbon held in all the earth's fossil fuels.

Testing the production capacity

The presence of gas

hydrates is commonly identified by bottom simulating reflectors (BSRs) in oceanic sediments.

©USGS Sampled and

inferred gas hydrates occur world wide in oceanic sediment of continental margins and in

permafrost regions. Inferred gas hydrates are from bottom simulating reflectors (BSRs) on seismic

profiles. The Mt. Elbert and Mallik test sites are located at the top of the map. ©USGSOnce the

presence of gas hydrates was confirmed and it had been shown that the

volume of gas is huge, the next question was if this resource be produced

and how. Significant technical issues stood in the way before gas hydrates

could be considered a viable energy source. Hoping to find the answers,

Canada, Japan, India, and the United State launched ambitious research

projects.  

"Past research has focused on three fundamental issues," according to Dr.

Collett. "Where do gas hydrates occur, how do they occur, and why do

they occur in a particular setting? However, there is a fourth issue. Until

recently, little had been done in evaluating the potential for viable

production of gas hydrates."  

In 2002, the U.S. Department of Energy and BP Exploration (Alaska), Inc.

(BPXA), in cooperation with the USGS, initiated a research program on

Alaska North Slope (ANS) gas hydrates. The ultimate goal was a

production test to determine if the gas hydrates could be a viable energy

resource.  

Three ambitious research programs have also been undertaken in the last

decade next door in the Mackenzie Delta at the Mallik research site. Led

by Canada and Japan, the 1150m deep Mallik 2L-38 well was completed in

1998. For the first time, cores were brought to the surface from an Arctic

gas hydrate occurrence delineating approximately 120m of hydrate

bearing section within coarse grained clastic sands.  

A second phase of this research program was undertaken in 2002 with a

broader five country partnership (Canada, Japan, Germany, USA, India)

that completed three additional wells and the first production test. This

would be the first time gas would be flared from hydrate.  

While the 1998 and 2002 Mallik gas hydrate research projects enabled

many new ground breaking studies, the flow rates were modest. Japan

(JOGMEC) and Canada (NRCan) therefore decided to return to the Mallik

site in the winters of 2007 and 2008 to initiate a new testing program

focusing this time on a full scale production draw down test.

The world's first

The Mt. Elbert-01

stratigraphic test well, Milne Point Unit on the North Slope of Alaska, collected the first open-hole

formation pressure response data in a gas hydrate reservoir. This test and reservoir simulations are

some of the first steps that could lead to production of hydrate reservoirs. Photo: Tim Collett,

USGS"We have now progressed way beyond just looking at the in-place

resources," says Dr. Collett. "Gas hydrate research is now looking at more

conventional prospects that can be produced by current technologies. The

February 2007 22-day field program at Mt. Elbert has taught us a lot about

how hydrates occur in porous media, why they occur where they do, and

the location and design of long-term testing."  

The field program at the Mt. Elbert site was designed to collect as much

data as possible from the gas hydrate zones. Researchers were able to

obtain a full suite of open-hole well logs, over 152m of continuous core,

and open-hole formation pressure response tests. They used chilled oil-

based drilling fluids to maintain excellent hole conditions and thus obtain

the best quality data.  

"We found approximately 30m of gas hydrate saturated, fine-grained sand

reservoir," says Dr. Collett. "Gas saturations ranged from 60% to 75%

mostly due to differences in reservoir quality."  

The culmination of the program was the open-hole tests. They were able

to obtain reservoir pressure response data in addition to gas and water

samples.  

"This well clearly demonstrated that open-hole data can be safely and

efficiently obtained from shallow, sub-permafrost sediments," says Dr.

Collett.  

Taking an even bigger step toward the production of methane from gas

hydrates was the Japanese and Canadian sponsored 2006-2008 Mallik 5L-

38 research well. Just completed in April 2008, the goal was to undertake a

longer production test than the 2002 Mallik project to advance new

research and development studies utilizing simple depressurization of the

reservoir.   "The first tests were conducted during the winter of 2007,"

says Dr. Scott Dallimore of the Canadian Geological Survey and lead

researcher for the Mallik Program. "Sand production prevented continuous

pumping. However, during a 12.5 hour interval, at least 830m³ of gas was

produced. It was the world's first gas production using large scale

depressurization of a gas hydrate."  

"After some modifications to the pumping system, 2008 field operations

were geared for a long duration test of the same 1093 to 1105 m depth

interval tested in 2007," Dr. Dallimore adds. "They were able to

continuously pump for six days until down-hole pressures stabilized. Gas

flowed to the surface and was flared while pressure, temperature, gas, and

liquid flow rate data were measured."  

The Japanese and Canadian team reported that the flow rates ranged from

2,000 to 4,000m³ per day. Cumulative gas production was over 13,000m³

for the six-day test.

Eileen trend prospects

"What the Mt. Elbert and the Mallik research is telling us is that we should

be able to develop gas hydrate prospects," says Dr. Collett. "When we

started the Mt. Elbert project, we first mapped 14 gas hydrate prospects in

the Eileen trend (Milne Point area northwest of the Prudhoe Bay field).

From 3-D seismic data and rock physics relationships conditioned by well

data, we were able to predict gas hydrate pay thickness and saturation.

The entire Eileen gas hydrate trend, including the 14 prospects in the

Milne Point area, has approximately 0.93Tm³ (33Tcf; 5.9Bboe) gas in place

with initial reservoir modeling suggesting as much as 0.34 Tm³ (12Tcf;

2.2Bboe ) recoverable."  

The Mt. Ebert prospect turned out to be the highest-ranked prospect in the

Milne Point area and was selected for the field data acquisition program.

This prospect had a strong and well organized seismic response.

Amplitude anomalies observed in two horizons were restricted within a

well defined three-way fault closure suggesting the accumulation was

originally a free-gas accumulation later converted to gas hydrate through

depressed thermal gradients associated with the development of

permafrost.  

Predictions were also made on individual reservoir sands that ranged in

thicknesses of 14 to 21m. The coring and logging program closely

confirmed these predictions.

Open-hole logs from the Mt. Elbert test clearly showing high resistivities in the gas saturated zones. The Unit D

sand had 68% gas hydrate saturation and Unit C 89%. The low resistivity sands below the Unit C, but still in the

hydrate stability zone, are water saturated. ©Tim Collett, USGSrnttttMap of the fault bounded amplitude feature

(yellow to magenta, yellow being the thickest and highest concentration of gas hydrate) defining the Mt. Elbert

prospect. ©Tim Collett, USGS

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More exploration

The successful research approach demonstrated at the Mt. Elbert well and

prospect has opened the door to more exploration and testing of gas

hydrate prospects.  

A 2-year program is underway to map, drill and log gas hydrate-bearing

sands in the deep water in the northern Gulf of Mexico. The project is the

latest phase in an ongoing Joint Industry project led by Chevron in

collaboration with the U.S. Department of Energy. They hope to further

test geological models and geophysical interpretations supporting the

existence of high gas hydrate saturations in reservoir-quality sandstone.  

Another recently completed study off the Indian continental margin has

confirmed the presence of gas hydrates in four offshore basins. Not only

did they find gas hydrates, they found one of the richest gas hydrate

accumulations yet documented (Krishna-Godavari Basin, Bay of Bengal)

and found the thickest and deepest gas hydrate stability zone near the

Andaman Islands also in the Bay of Bengal.  

Significant resource opportunity

Amplitude anomalies

associated with the gas hydrate drilling targets at the C Horizon. The anomalies are restricted

within a well defined three-way fault closure. ©Tim Collett, USGS"For years, gas hydrate

research has been framed by extravagantly large numbers (see above)

that refer only to the in-place volumes of methane in gas hydrates," says

Dr. Ray Boswell, Manager-Methane Hydrate R&D Programs, U.S.

Department of Energy.  

"These volumes are significant in an environmental context, and the

climate implications of gas hydrates are a major topic of study in the U.S.

effort. However, in the context of potential resources, what is most

interesting is what portion of that resource is a realistic future source of

gas supply. The array of recent field programs, combined with continuing

work in the lab, is now providing the first insight into those technically-

recoverable volumes. Although these numbers lack eye-popping appeal,

they clearly indicate significant new resource opportunities that, given its

global distribution, have the potential to alter existing energy production

and supply paradigms," says Dr. Boswell.  

"After a decade of R&D studies at Mallik, we have addressed many

scientific unknowns and established proof of concept that gas hydrate

production can be sustained with the pressure draw down technique, using

conventional oil and gas production techniques modified to accommodate

the unique physical properties of gas hydrates," Dr. Scott Dallimore adds.  

"However, our testing at Mallik was only for six days duration. The next

milestone advances in production research are likely to come through

longer testing which will allow consideration of the field-scale response as

well as providing a basis to consider environmental issues associated with

production. It is my understanding that longer term testing programs are

actively being considered in northern Alaska, the Mackenzie Delta and

even in offshore settings like the Nankai Trough (offshore Japan)."

Long term endeavour

"Natural gas demand is expected to grow in the first decades of this

century as production from conventional sources decline," concludes Dr.

Tim Collett. "Vast deposits of marine and arctic gas hydrate are seen as a

possible source of natural gas, but there are many challenges to be

overcome before widespread production of natural gas from gas hydrate

are possible. The evaluation of gas hydrate as an energy source is clearly

a long-term endeavour that will require significant financial investment."

Hydrates and the petroleum system"Recent research has helped address key issues of the formation, occurrence, and stability

of naturally occurring gas hydrates," says Dr. Collett. "The concept of a ‘gas hydrate

petroleum system' is well within our reach. The source, migration, reservoir, trap, and

timing as in any petroleum system must be examined when developing exploration plays.

One further consideration, the gas hydrate pressure-temperature stability conditions must

also be accounted for." Indeed, most of the recent literature examines these factors when

dealing with gas hydrates.  

Gas hydrate stability conditions:The depth to the base of the gas hydrate stability zone (GHSZ) can be calculated from

down-hole temperature data and the pore pressure gradient. In most areas, the calculated

depth to the base of the GHSZ corresponds closely to the depth of the BSR inferred from

seismic data.  

The Petroleum SystemSource: Abundant methane gas sourced from either biogenic or thermogenic or both is

an important factor to the distribution of gas hydrates. Much of the offshore data points to

more biogenic origin for the methane gas; however both sources have been identified

through carbon isotope analyses.  

Migration: Like any accumulation, there must be a way to get the hydrocarbons to the

reservoir. Migration pathways for both gas and water are a must for significant hydrate

volumes to accumulate. Many areas show gas hydrates to be closely associated with

structural features where gas and water can migrate through a fracture or fault system.

This can also be confirmed on a macroscopic to microscopic scale as most hydrates

recovered are either pore-filling in coarser grained sediments or fractured-filling in more

fine grained sediments.  

Reservoir: High saturations of gas hydrates are consistently associated with high

porosity and permeability reservoirs, either good quality sand-rich sediments or fractured

mudstones.  

Trap: Most high concentrations of gas hydrates in permafrost environments are

associated with some type of trapping mechanism. The traps being considered for early

exploration have been mostly structural as was the case with early conventional

hydrocarbon plays.  

Timing: Finally, as with any accumulation, the geologic history has to be such as to trap

and preserve the migrated hydrocarbons.

Gas hydrates concentrate along porous and permeable zones such as fractures (core from India on top) to the good quality

conglomeratic sandstones found in the Mallik well. Photos: Tim Collette, USGS and 2006-2008 Canada-Japan Mallik Project

Gas Hydrates - Part I: Burning Ice

In a series of articles we will explain in a simple way what gas hydrates

are, where they can be found in nature, and what their physical properties

are. Natural gas hydrates are a potential source of energy and may play a

role in climate change and geological hazards. A number of countries,

including Japan, USA , India, China, Korea, Germany, and others, have

national programmes for studying and industrial production of natural gas

from hydrates.

Doubted by Experts

Yakutia, or the Sakha Republic, is a vast unexplored region of Siberia in

the north-east of Russia. It is one of the rare places left on Earth where

large expanses of wild nature – mountains, rivers, lakes, forests, tundra –

are saved untouched by civilisation. Yakutia is located in a permafrost

zone, although the climate is continental, with summer temperatures in

July in the city of Yakutsk reaching 40°C, as hot as Tokyo, while in winter it

goes down to -50°C. 

The wild mountain landscape of Siberian taiga along the Lena River in Lenskie Stolby National Nature Park, Yakutia, Russia. Source: Tatiana Grozetskaya / Dreamstime.com

Yakutia is where we find the Cold Pole, the coldest place in the northern

hemisphere, where in 1924 the lowest ever temperature for our

hemisphere, -71.2°C, was recorded. Here, beyond the Polar Circle, the

night lasts all winter, and the day all summer. 

It is 1963, and Yuri Makogon, then at the Moscow Oil-Gas Gubkin Institute

with a fresh MSc degree in petroleum engineering (now recently retired

from Texas A&M University), is staying in the north-western part of

Yakutia. He participates in the drilling of the Markhinskaya well, down to

1,800m depth where the temperature is 3.8°C. The well reveals a section

of rock at 0°C temperature at a depth of 1,450m, where permafrost ends

at a depth of around 1,200m. Yuri recognises that this section of the rock

matches hydrate formation conditions. He hypothesises the possibility that

gas hydrates can exist and accumulate in such cold layers. His hydrate

hypothesis is seriously doubted by the experts, and the idea needs

experimental verification, so in 1965 Yuri experimentally proves that gas

hydrates may accumulate as large natural deposits in porous rock. In 1969

this discovery is formally recognised and registered in the USSR. Yuri is

today recognised as the first to discover that hydrates of natural gas can

accumulate as deposits in nature.

Easy Rapid Process

Thermogram of the Markhinskaya No. 1 well. Source: Makogon,

1966Monterey Canyon is a submarine canyon in Monterey Bay, California. It

begins at the middle of the Monterey Bay, and extends 153 km into the

Pacific Ocean where it terminates at the Monterey Canyon submarine fan,

reaching depths of up to 3,600m below surface level at its deepest. The

canyon’s depth and nutrient availability due to the regular influx of

nutrient-rich sediment provide a habitat suitable for many marine life

forms. 

In 1996, the remotely operated vehicle (ROV) Ventana comes to rest in the

Monterey Bay Canyon at 910m depth where the temperature is 4°C.

Operated by scientists from Monterey Bay Aquarium Research Institute,

Stanford University, and the US Geological Survey, an amount of methane

is injected into the water and bottom sediments. Within minutes, this

mixture of gas and water forms into a solidified block, bright white and

fluffy. The experiment shows not only that in natural seawater but that the

process is extremely easy and rapid, given that the pressure and

temperature conditions are right. Prior calculations had shown that the

local hydrographic conditions gave an upper limit of 525m for the

pressure-temperature (P-T) boundary defining methane hydrate formation

at this site, and thus the experiment takes place well within the stability

range for this reaction to occur.

A massive hydrate layer obtained from fine-grained sediment recovered in a marine setting in the Gulf of Mexico.

Bill Winters, USGS

Compared to hydrate recovered in a coarse-grained gravel layer from an Arctic setting, the Mallik 2L-38 well,

drilled in the Northwest Territories of northern Canada. Bill Winters, USGS

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Gas Hydrates

A model of methane hydrate’s cage-like

structure in which methane (the grey/green molecule) is enclosed inside a lattice of water (the red

molecules). This ‘unit cell’ joins together with other unit cells by sharing faces to build the hydrate

solid, even at temperatures well above the melting point of water ice. When gas hydrates

dissociate (melt), the crystalline lattice breaks down into liquid water (or ice) and the gas is

released. Jarle Husebø, StatoilA model of methane hydrate’s cage-like structure in

which methane (the grey/green molecule) is enclosed inside a lattice of

water (the red molecules). This ‘unit cell’ joins together with other unit cells

by sharing faces to build the hydrate solid, even at temperatures well

above the melting point of water ice. When gas hydrates dissociate (melt),

the crystalline lattice breaks down into liquid water (or ice) and the gas is

released. Jarle Husebø, Statoil

You are familiar with ice: it is cold, hard, slippery, and buoyant. You can

find icebergs and ice floes on the surface of the ocean in polar regions. But

there is another, higher-pressure form of ice trapped at and beneath the

seafloor that is far less familiar. This ice, which is known as gas hydrate, is

created by the reaction of gas – predominantly methane – with water at low

temperature and high pressure to form a crystalline solid. Such compounds

are a common occurrence buried in permafrost and continental slope

sediments around the world ocean. For methane hydrate, the water and

gas combine in a ratio of six molecules of water to one of gas. The gas

draws in the water molecules to form a cage within which the methane

molecule flutters in a strange molecular dance, feeling the attraction and

pull of the hard ice walls of its prison, but without ever touching. Most

natural gas hydrate appears to be in this structure, with methane as the

trapped guest molecule, although alternative structures have also been

identified, with guest molecules such as isobutane and propane, as well as

lighter hydrocarbons. Gas hydrates provide an extremely effective way of

storing natural gas or methane (CH4). At standard atmospheric

temperature (20°C) and pressure (1 atm) conditions, 1 m³ of solid methane

hydrate is equivalent to 160 m³ of free gas. Although global estimates

range widely by more than two orders of magnitude, the most cited value

is that of Kvenvolden in 1988, at 2x1016 m³ of gas, or 10,000 gigatons of

carbon. In comparison, estimates for the known combined reserves of

conventional hydrocarbons (natural gas, oil, coal) are about half of that

value.

An Unusual Catch

Barkley Canyon is located off Vancouver Island, Canada, on the northern

typically sites of underwater landslides as well as movement of sediment,

organic material and nutrients to the deep ocean. The upwelling of

nutrients driving the region’s rich biodiversity makes the upper slope a

crucial study area for scientific and environmental policy purposes. It also

makes it a popular region for commercial fishing.

One November day in 2000 the vessel Ocean Selector is trawling over the

Barkley Canyon in an area of 800m water depth. (Trawls are fishing nets

that are pulled along the bottom of the sea or in midwater at a specified

depth). When the captain pulls up the net, the crew see the most unusual

catch: over a ton of strange white solid that fizzes and crackles on the

deck. They shovel it overboard, fortunately without harm. The crew has by

accident discovered a large seafloor deposit of methane hydrate. If one of

the seamen had lit his smoke it could had resulted in a disaster as the

crackling actually released significant amounts of methane gas. 

Methane is a fuel, and despite being trapped in an ‘ice’, it will readily burn.

For this reason, methane hydrates are known as burning ice. 

That day in November introduced the scientific community to a new,

massive seafloor outcrop of gas hydrate on a 500m wide, 1 km long

plateau perched 150m above the canyon floor. In 2004, Canadian

scientists explored and verified the site, and the ROV revealed pinnacles

cutting up through the seafloor. Massive outcrops are exposed in 1–2m

high mounds covered by a thin veneer of sediment. A light yellow

condensate fluid is present in the surrounding sediment and associated

with the hydrate, causing yellow staining. With buoyant hydrate slabs on

the seafloor reaching 7m in length and 3m in height and with only a thin

sediment cover, the hydrate mass must continue deeper and be anchored

below the surface. 

Although methane hydrate is known to be stable at the sea floor for water

depths greater than 500–600m at temperate latitudes, observed outcrops

of hydrate at the sea floor are rare and somewhat poorly understood.

Gas Hydrate Stability Zone (GHSZ)

Permafrost - Methane gas hydrate stability zone (GHSZ) forpermafrost and marine settings. The pressure-

temperature phase boundary (idealised) is shown as a green curve, and the local thermal (assumed) gradients are

in red. In permafrost, the GHSZ can begin at 100–300m depth and extend for hundreds of meters beneath the base

of the permafrost (typically occurring at 150–600m depth). Source: Courtesy SEG

Marine - In marine sediments, the GHSZ typically begins below 300–600m and extends for hundreds of meters. The

thickness of the marine GHSZ depends on sea floor water temperature (typically 3–4°C), salinity, geothermal

gradient and depth. Source: Courtesy SEG

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Gas hydrates are stable only under high-pressure and low-temperature

conditions. The region where gas hydrates are stable – the gas hydrate

stability zone (GHZS) – is defined by the intersection of the pressure-

temperature phase boundary and the local geothermal gradient. Because

of the nature of the conditions for stability, gas hydrates are usually found

only in permafrost regions and on continental slopes where water depth

exceeds 300–500m.

As shown in the figure for the marine setting, the top of the GHSZ occurs

above the sea floor. However, the ocean water does not contain enough

gas to stabilise hydrate and the top of the GHSZ is normally defined at the

sea floor. Here, the temperature is normally 3–4°C. Going down into the

sediment, the temperature slowly increases; the global average of the

geothermal gradient is 0.02°C/m. While the pressure increases with depth,

after 500–1,000m depth the temperature becomes too high for hydrates to

remain stable. This is the base of the GHSZ.

In permafrost, the situation is similar. The top of the GHSZ is where the

temperature line crosses the hydrate stability line, often beginning at 100–

300m depth. The GHSZ typically extends for hundreds of meters. The

depth of the GHSZ is also related to the base of the permafrost, which is at

0°C. The deeper the base of the permafrost the deeper the GHSZ becomes.

Gas Hydrates - Part II: Rock Physics, an Introduction

A major and obvious difference between ice and hydrate is that the

hydrate is highly flammable (‘burning ice’).

It is of course the methane content in hydrate that makes it of commercial

interest. In fact the difference between ice and methane hydrate is not

huge: one could consider hydrate as one dash of methane gas and six

dashes of pure ice. Ice has a hexagonal crystalline structure, with a

density of roughly 0.92 g/cm3 at 0°C and increases to 0.93 for a

temperature of -180°C. The density of methane hydrate is slightly less

(0.90 g/ cm3), since there is only 1 mole of methane per 5.75 moles of ice.

Another way to formulate this is to say that whereas ice has the formula

H2O, the empirical chemical formula for methane hydrate is (CH4)8(H2O)46.

So, if the density difference between ice and hydrate is negligible, what

about other crucial seismic parameters, such as velocities?

Rock Physics Experiments

In 2001 Michael Helgerud presented a comprehensive PhD thesis at

Stanford where he analyzed wave velocities in gas hydrates and

sediments containing gas hydrates.

For pure gas hydrate samples made in the laboratory he measured P-wave

(compressional) velocities around 3700 m/s and S-wave (shear) velocities

around 1950 m/s. Only small variations with temperature and confining

pressure were observed.

The ratio between P-wave velocity of pure hydrate versus ice is 0.98. For

the S-wave velocity the corresponding ratio is close to 1.0. This means

that, acoustically, pure ice and pure methane hydrate are very similar.

This is maybe as expected since the dominant crystalline structures of the

two are similar.

Compressional and shear velocity versus time. The figure shows the response to a warming of the sample from 5

to 20°C followed by a cooling back to 5°C again. Confining pressure: 9,000 psi. Source: Helgerud (2001)

Compressional and shear wave velocities versus confining pressure for methane hydrate. The horizontal scale is

from 4,000 to 9,000 psi. Source: Helgerud (2001)

Compressional and shear velocity versus time. The figure shows the response to a warming of the sample from 5

to 20°C followed by a cooling back to 5°C again. Confining pressure: 9,000 psi. Source: Helgerud (2001)

Compressional and shear wave velocities versus confining pressure for methane hydrate. The horizontal scale is

from 4,000 to 9,000 psi. Source: Helgerud (2001)

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Rock Physics

Rock physics provides the connections between geophysical (elastic and

electromagnetic) properties of the rock measured at the surface of the

earth, within the borehole or in the laboratory, with the intrinsic properties

of rocks, such as mineralogy, porosity, pore shapes, pore fluids, pore

pressures, permeability, electrical resistivity, viscosity, stresses and overall

architecture such as laminations and fractures. These parameters affect

how seismic and electromagnetic waves/fields physically travel through the

rocks. Establishing relationships between geophysical expression and

physical rock properties therefore requires knowledge about the

elastic/electromagnetic properties of the pore fluid and rock frame, and

models for rock-fluid interactions.

Equations that attempt to describe the relationships between seismic

velocities and lithology, porosity, pore fluid, etc. are either theoretical or

empirical.

Zhijing Wang summarizes the tension between theoretical and empirical

approaches this way: most direct measurements are carried out either in

the laboratory or inside a borehole, whereas most theoretical calculations

are based on the Gassmann equation (Gassmann, 1951) because of its

simplicity and ease of use. Direct laboratory measurements are carried out

in controlled, simulated reservoir environments and provide accurate

effects of pore fluids on seismic properties. Direct borehole measurements,

however, are often affected by uncontrollable factors such as stress

concentration, hole washout, mud invasion/filtration, and saturation

conditions. In both laboratory and borehole measurements, the wave

frequencies are higher than seismic frequencies.

Jan Dewar summarizes that the crux of all this is that there are a great

number of relationships between seismic velocities (and constituent elastic

properties) and rock parameters, all valid to some degree but not always

valid, and many that do not illuminate the physical principles involved. The

trick is to try to gain a fundamental understanding so that, on a practical

basis, the different relationships can be evaluated for their applicability to

solving specific problems.

Theoretical rock physics modeling can also be applied to understand the

physical properties of natural gas hydrate systems and accumulations. A

major goal is to establish linkages between gas hydrate

concentration/saturation in sediments and the measureable physical

properties, like P- and S-wave velocities and electrical resistivity. Modeling

the elastic properties of sediments as a function of gas hydrate content can

be achieved in various ways, such as effective medium modeling or three-

phase Biot theory. The effective medium theory can incorporate the effects

of cement and grains. In the case of gas hydrate, the hydrate can form in

various ways. The effective seismic velocities vary quite strongly

depending on which formation scenario is used.

To model gas hydrate systems via rock physics one needs to define the

elastic/electromagnetic properties of the system in terms of (i)

elastic/electromagnetic properties of the (unconsolidated) sediments that

host the hydrates, (ii) elastic/electromagnetic properties of the embedded

gas hydrates, (iii) the concentration of hydrates in the sediments, and (iv)

geometrical details of the distribution of hydrates within their host

sediments. The inverse modeling problem is to infer hydrate concentration

from geophysical measurements.

Acoustic well-logs with full waveform show a pronounced decrease of wave

amplitude in hydrate-bearing zones.

Compressional and shear velocity versus porosity for ice. Source: Helgerud (2001) P-wave velocity versus

porosity assuming that the methane hydrate is a part of the rock frame (black line), of the pore fluid (green line).

The red line shows a rock which is 100% water saturated (no hydrate), the blue solid line represents 1% patch

gas saturation, and the dark blue line represents 1% homogenous gas saturation. Source: Helgerud (2001)

Compressional and shear velocity versus porosity for ice. Source: Helgerud (2001) P-wave velocity versus

porosity assuming that the methane hydrate is a part of the rock frame (black line), of the pore fluid (green line).

The red line shows a rock which is 100% water saturated (no hydrate), the blue solid line represents 1% patch

gas saturation, and the dark blue line represents 1% homogenous gas saturation. Source: Helgerud (2001)

1.

2.

Fluid, Frame or Cement?

Is hydrate a part of the fluid, the frame or is it cement?

We have seen that pure hydrate and ice are very similar with respect to

traditional seismic parameters, such as velocities and densities. However,

in nature, the hydrate is found as a part of a rock, making the rock physics

relations more complex. What happens when methane hydrate enters into

a sedimentary rock? Hydrate is found both in clay rich sediments and in

sands. Several models have been proposed for this, varying from

regarding the hydrate as a part of pore fluid fill, via being a part of the

rock frame or acting as cement between sand grains. Helgerud found that

the P-wave velocity is slightly higher when assuming that the hydrate is a

part of the rock frame.

There are two ways of addressing this problem: either to perform

measurements in wells drilled into hydrate-bearing rocks, or to inject

hydrate in a controlled way into a rock in the laboratory. We will discuss

both methods in the next issue of GEO ExPro.

1.

2.

In this box we show two examples of some of the most frequently used

rock physics relations. The most famous model in rock physics is the

Gassmann (1951) equation, which is used to describe the effect of

gradually changing the pore fluid in, for instance, a sandstone. It needs

calibration prior to use, for which we often use well logs. The figure on the

right shows how the relative P-wave velocity varies as a function of water

saturation, assuming that the pores are filled with either oil or water.

Another key reservoir parameter is the pore pressure. For wave velocities it

turns out that it is the effective pressure (which is approximately equal to

the overburden pressure minus the pore pressure) that controls the

velocity. The simplest version for a theoretical model that includes changes

in effective pressure is the Hertz-Mindlin model. This is a contact model,

where it is assumed that the rock grains are identical spheres with a given

contact area that increases with the effective pressure. As this contact area

increases, the velocity increases, as shown below. The black line

corresponds to a Mindlin-coefficient of 1/6 and the red line to 1/10,

demonstrating that also in this case we need a calibration procedure prior

to practical application of this simple model. In most cases we assume that

the density does not change as the pore pressure changes. However, in

some cases the rock might compact or undergo stretching, and in such

cases the porosity will change and hence also the density. Typical

examples are chalk reservoirs that may compact by several meters, due to

production. Rock physics plays a crucial part both in exploration and

production geophysics: advanced and quantitative use of, for example, pre-

stack seismic data require rock physics input to link the seismic parameters

to key reservoir parameters such as saturation, pressure and porosity.

Gas Hydrates - Part III: Rock Physics Hydrate Experiments

In the previous issue of Geo ExPro we discussed whether gas hydrate is a

part of the pore fluid or a part of the rock itself. It was shown that this

matters if we want to estimate geophysical parameters for a gas hydrate

rock. There are two ways (at least!) to investigate this further: either to

observe geophysical parameters from wells being drilled through a

hydrate-bearing rock, or to inject methane hydrate into a rock sample in

the laboratory. We will discuss examples of both and put particular

emphasis on a recent lab experiment performed in China.

Seismic Attenuation

Like the presence of free gas, the presence of gas hydrate affects seismic

attenuation. Attenuation has the potential to map hydrate concentrations

through the effect of local blanking of sediment stratigraphic reflectivity.

However, there are few studies related to seismic attenuation in hydrate-

bearing sediments and it remains an open topic for future studies. The

attenuation of seismic energy by gas hydrates is likely to depend on the

concentration of hydrate, the thickness of hydrate, the mechanism of

hydrate formation, and the dominant frequency of the seismic

measurements, in addition to the lithology changes.

VSP data in the Mackenzie Delta indicate that quite thick hydrate-bearing

zones have significant attenuation at seismic frequencies of 10–200 Hz (Q-

values, which describe inverse attenuation, of around 10).

Observations from Wells

Methane hydrate

concentration in the sediments at ODP site 995 from P-wave sonic and resistivity logs. Column 1:

Comparison of P-wave velocity (red line) with model results assuming methane hydrate (solid black

lines) or homogeneously distributed methane gas (dashed lines) are part of the pore fluid. Column

2: Comparison with model results assuming methane hydrate is a sediment frame component (solid

black lines) or methane gas is patchily distributed in the pore space (dashed lines). Column 3:

Comparison of methane hydrate concentration estimates derived from the resistivity log to

estimates derived from the compressional wave sonic log using the gas hydrate as sediment frame

component model. Source: Helgerud, 2001In a field example from a well drilled at the

Blake Ridge (ODP site 995) offshore South Carolina, USA, Helgerud found

that the rock physics model that assumes hydrate is part of the rock frame

gave a reasonable fit between hydrate concentrations estimated from P-

wave well log measurements and those obtained from the resistivity log.

The deviation between the two models is not huge, but based on the well

log observation it is clear that the model which assumes hydrate is part of

the rock itself and acts as a kind of cement explains the well log data best.

A relative good fit between observed saturations of hydrate and those

estimated using the Archie equation (discussed in more detail below) is

achieved.

Qingdao Experiment

This year, a very interesting experiment on hydrate formation and

dissolution was presented by Hu and Ye of the Qingdao Institute of Marine

Geology in China. They measured P- and S-wave velocities as the hydrate

concentration in two rock samples was gradually increased from zero to

70%. The sediment samples were first immersed by pure water, then

loaded into a high-pressure vessel, and injected with methane. The

temperature was kept at 2°C for hydrate formation. To simulate the effect

of hydrate dissolution, the temperature was gradually increased to room

temperature.

Microstructural Models

Existing

microstructural models of gas hydrate-bearing sediments (adapted from Dai et al., 2004).

Observations from various fields show that gas hydrate mainly forms as a supporting matrix-grain

(scenario 3). Source: Lasse AmundsenHigher gas hydrate concentrations yield an increase in

the elastic properties. There are a number of rock physics models in the literature that

attempt to quantify this effect (Dai et al., 2004). The ‘cementation models’ treat the grains

as randomly packed spheres where the gas hydrates occur at the contact point (model 1)

or grow around the grains (model 2). However, these models predict large increases in the

elastic properties with only a small amount of gas hydrate but stay relatively flat as the

concentration of gas hydrate increases further.

Models 3 and 4 are variations of the cementation models, but consider the gas hydrate as

either a component of the load-bearing matrix or filling the pores. These use the Hertz-

Mindlin contact theory to calculate dry rock moduli at critical porosity (35–40%). A

modified lower Hashin-Shtrikman (HS) bound is used for porosity smaller than critical

porosity, and a modified upper HS bound is used for porosities larger than critical porosity.

The Gassmann equation is then used to derive the composite rock velocities.

Model 5 is an inclusion-type model that treats gas hydrate and grains as the matrix and

inclusions respectively, solving for elastic moduli of the system by iteratively solving either

the inclusion-type or self-consistent type equations.

Models 1–5 all consider gas hydrate as homogeneously distributed in the sediments.

However, evidence of gas hydrate coring reveals that hydrates often exist as nodules and

fracture fillings in the shallow shaly sediments. This geometry is illustrated in model 6. No

quantitative treatment of this geometric model exists in the literature.

P- and S-wave

velocities versus hydrate concentration for a consolidated sand sample. Source: Hu and Ye, 2012

P- and S-wave

velocities versus hydrate concentration for an unconsolidated sand sample. Source: Hu and Ye,

2012

For an unconsolidated sand sample, they found that the P-wave velocity

increased from approximately 1,600 m/s for zero hydrate concentration to

approximately 3,600 m/s for 70% hydrate concentration. The

corresponding values for the S-wave velocity were 600 and 1,600 m/s,

respectively. This means that the Vp/Vs-ratio decreases from 2.7 for no

hydrate to 2.25 at 70% hydrate concentration. For comparison, it is

interesting to note that Helgerud (2001) measured a Vp/Vs-ratio of

approximately 1.9 for pure hydrate. A linear extrapolation of the measured

Vp/Vs-ratio from Hu and Ye’s experiment yields a Vp/Vs-ratio of

approximately 2.0.

For the consolidated sample, the Qingdao experiment showed, as

expected, higher acoustic velocities: a P-wave velocity increase from

4,250 m/s to 4,700 m/s as the hydrate concentration is increased from 0 to

70%. The corresponding numbers for the S-wave velocity are 2,500 m/s

and 2,750 m/s. These numbers correspond to a constant Vp/Vs-ratio of

approximately 1.7, practically independent on hydrate concentration.

Hu and Ye also noticed a hysteresis effect for the P-wave velocities. For

the unconsolidated sand sample they found that for a hydrate

concentration of 50% the P-wave velocity was 2,700 m/s as hydrate was

formed and only 2,000 m/s as hydrate was dissolved. The S-wave velocity

showed a similar, but weaker hysteresis effect. For the consolidated

sample they found that this hysteresis effect was opposite: the P-wave

velocity during formation of hydrate was lower than the corresponding

value for dissolution. Hu and Ye suggest that this hysteresis effect is

caused by two very different mechanisms for unconsolidated and

consolidated rocks. For unconsolidated rocks they suggest that the high

velocity during formation is caused by hydrate cementation, and that this

cementation process behaves differently during formation and dissolution.

For consolidated rocks they discuss a two-stage formation process of

methane hydrate: first a water-hydrate slurry is formed, followed by a slow

solidification process. This two-stage process might explain that P-wave

velocities are lower during formation compared to dissolution for the same

hydrate concentration. These results are interesting, and might be of

importance for geophysical analysis of data from hydrate-bearing

sediments. A velocity difference of 700 m/s related to whether hydrate is

slowly dissolving or being formed should be possible to detect. For

instance, if a hydrate-bearing rock is being produced by heating the rock,

hydrate will start to dissolve, and a significant change in P-wave velocity

should be detectable on conventional time lapse seismic data. This

depends of course on the initial concentration of hydrate within the porous

rock; for low concentrations the changes in P-wave velocity will be less

pronounced, as demonstrated by Hu and Ye’s experiment.

Resistivity Variations

Nigel Edwards is one of the pioneers in investigating the

mapping of submarine hydrates using electromagnetic surveying methods.

In 1997 he published a paper describing how seafloor transient electric

dipole-dipole methods can be used to detect hydrates. He uses a

simplified version of the Archie equation (see box above) to assess the

effect of methane hydrate concentration (Sh) on the formation resistivity

():

Here, is the resistivity of the sea water (0.3 Ohm-meter) and denotes

porosity. We clearly see from this equation that the formation resistivity

increases rapidly as the hydrate concentration increases, a fact that

makes methane hydrates a candidate for electromagnetic surveying and

complementary to seismic surveying. Spangenberg and Kulenkampff

(2006) use artificial samples (glass beads) to measure the resistivity

versus hydrate concentration. They found that the resistivity increased

from 5.1 Ohmm at zero percent hydrate saturation to 265 Ohmm at 95%

hydrate saturation. They also investigated the accuracy of the Archie-

equation given above, and found that the exponent (equal to 2 in the

above equation) deviated significantly from 2, especially for hydrate

saturations above 50%, where an exponent above 4 was found.

Archie’s Equation

Rock physicists talk about velocities and elastic parameters, because

these are what link physical rock properties to seismic expressions. Petrophysicists are

generally less concerned with seismic, and more concerned with using wellbore

measurements to contribute to reservoir description.

In the field of petrophysics, Archie’s equation relates the in-situ electrical conductivity of a

sedimentary rock to its porosity and brine saturation. Named after Gus Archie (1907–

1978), his empirical relationship laid the foundation for modern well log interpretation as it

relates borehole electrical conductivity measurements to hydrocarbon saturations.

Archie’s relation for gas hydrate–bearing sediments reads:

where is the true or measured bulk formation resistivity, is the pore fluid resistivity, is the

sediment porosity, 0.5 < a < 2.5 is a constant, and 1.5 < m < 3 is the cementation factor

that increases as the grains becomes less spherical with depth. Sh is the hydrate

concentration. The value of n depends on the grain-hydrate-fluid structure. If n is relatively

large, gas hydrate forms in a way that strongly impedes current flow and increases bulk

sediment resistivity (e.g., gas hydrate located in the pore throats), whereas if n is

relatively small, gas hydrate forms in a way that has a lesser effect on sediment resistivity

(e.g., gas hydrate occurrence in the pore space, making minimal contact with sediment

grains). Pearson et al., (1983) calculated an estimate for n of 1.94; however, modelling by

Spangenberg (2001) has shown that n depends somewhat on grain size distribution and

the gas hydrate saturation itself.

In practice, for marine sediments, the pore fluid resistivity usually can be adequately

estimated from the equation of state of seawater, if in-situ pressure, temperature and

salinity are known. The gas hydrate saturation now can be estimated directly from the

equation above, given that the empirical Archie parameters a, m and n are known.

Gas Hydrates Part IV: Where Are Gas Hydrates Found?

While research on methane hydrates is still in the early stages, these

research efforts… could potentially yield significant new supplies of natural

gas and further expand US energy supplies.”

On August 31, 2012 US Secretary of Energy, Dr. Steven Chu, announced

an investment of $5.6 million in research on methane hydrates.

From Part I (GEO ExPro Vol. 9, No. 3) of our series on gas, the key learning

is that four ‘magic ingredients’ must be present for gas hydrates to exist.

They form when there is a sufficient supply of water and gas,

predominantly methane (99%), at relatively low temperatures and high

pressures, with temperature and pressure in the so-called Gas Hydrate

Stability Zone (GHSZ), (see box, p34). Favourable hydrate formation

conditions exist off the coasts on the continental margins and below the

permafrost.

In marine settings, temperature is controlled by the ocean bottom water

temperature and the geothermal gradient at any given location, while

pressure is controlled by sea level. In aquatic sediment where water

depths exceed about 300m and bottom water temperatures approach 0°C,

gas hydrate is found at the seafloor to sediment depths of about 1,100m.

The general temperature range is from 2 to 20°C.

In a permafrost setting, however, temperature gradients are considerably

lower than in the ocean. The ambient temperature and the thickness of

the permafrost layer therefore are of significant importance for the

stability of gas hydrate. In polar continental regions, methane hydrate can

occur at depths ranging from 150 to 2,000m, with a general temperature

range from -10 to 20°C.

Bottom Simulating Reflector (BSR)

Distribution of known

methane hydrate accumulations. The yellow dots show where actual samples of gas hydrate have

been recovered whereas the red dots show where gas hydrate occurrences have been inferred

based on BSRs and well logs. It is evident that gas hydrates are found along most continental shelf

and slope regions and in many permafrost areas. Hydrates have also been found in inland seas

(e.g., Black Sea and Caspian Sea) and in fresh water lakes (Lake Baikal). (Courtesy of Council of

Canadian Academies (2008), based on data from Kvenvolden and Rogers, 2005.)

Seismic example of

Bottom Simulating Reflector (BSR), from Indonesia. The water depth is 1,800–2,000m. Observe that

the BSR has opposite polarity to that of the seabed. The average thermal gradient, about 35°C,

permits the gas hydrate to exist down to around 300m sediment depth – below that temperature is

too high and methane can exist only as free gas. Source: Statoil IndonesiaThe geothermal

gradient is important. At a certain depth in ocean sediment the

geothermal gradient makes the sediment too warm to support the solid

gas hydrates, so any methane produced below this depth will be trapped

as a layer of free gas in the pore space beneath the solid gas hydrate

layer. Often, but not always, the interface between the gas hydrate and

the free gas is an anomalous seismic reflector called a Bottom Simulating

Reflector (BSR), as this reflector necessarily is roughly parallel to the

seafloor morphology along isotherms. BSRs therefore need not follow the

trend of stratigraphic horizons, but may intersect them.

In seismic sections, BSRs are usually characterized by large amplitudes

but exhibit reversed polarity compared with the sea-bottom reflection.

The BSR indicates the lower boundary of gas hydrate stability.

Consequently, gas hydrate is often assumed to exist above the BSR;

otherwise, the free gas below the BSR would have migrated upwards. But,

while a BSR does illustrate the volume of sediment inside the stability zone

it does not provide information on the actual hydrate saturation in-place.

BSRs can be observed even when very little hydrate is present, and BSRs

need not always be observed in hydrate-bearing sediments.

Exploration for Gas Hydrates

Gas hydrate saturation

of the pore space. Source: modified from Klauda & Sandler (2005)

Predicted thickness of

the global GHSZ. The thickest zones (600–800m) are mainly situated in high-latitude regions (Arctic

and Antarctic) due to low bottom water temperatures which maintain conditions required for

hydrate formation. Extended GHSZs are also observed along continental margins (>500m) where

thick sedimentary sequences are deposited. In these settings the extent of the GHSZ is not limited

by sediment thickness so that free gas can accumulate in sediments below it. Note that this

definition of the global GHSZ gives an upper limit to possible gas hydrate occurrences. Source:

modified from Burwicz et al 2011To date, around 100 sites have been identified as

containing gas hydrate deposits. Samples have been taken at

approximately 20 different sites, while at another 80 sites the existence of

gas hydrate has been suggested by seismic evidence, in the form of BSRs.

Exploration for gas hydrates is not much different from exploration for

conventional hydrocarbons: important factors to recognize are source,

migration, reservoir, and seal.

If there is not sufficient gas supply, there will be no gas hydrates. Two

distinct processes produce hydrocarbon gas: biogenic and thermogenic

degradation of organic matter. Biogenic gas is formed at shallow depths

and low temperatures, up to 75–80°C, by anaerobic bacterial

decomposition of sedimentary organic matter. It is very dry and consists

almost entirely of methane. In contrast, thermogenic gas is formed at

deeper depths, much deeper than the GHSZ, in the temperature range 50–

200°C by thermal cracking of sedimentary organic matter into

hydrocarbon liquids and gas. This type of gas, which is common in

conventional gas reservoirs, can be dry, or can contain significant

concentrations of ‘wet gas’ components (ethane, propane, butanes) and

condensate.

Fluid migration from the source through faults, folds, and fractures into the

GHSZ plays a critical role in the formation of a gas hydrate accumulation.

Rapid gas transport is required to concentrate gas in permeable reservoir

sediments where gas hydrate crystallizes. Water transport is usually

thought to be less important because water is virtually omnipresent in

sediments, although it may be a limiting factor for gas hydrate

crystallization in some areas. Sand-rich reservoir environments are better

than clay-dominated systems. As far as seals are concerned, gas hydrates

themselves are the seals.

The possibility of production from hydrates is highly dependent on the

particular reservoir characteristics. Many of the known marine deposits are

probably unfeasible for hydrate production. The candidates that are

currently being explored are high concentration accumulations in coarse-

grained sand environments with high porosity and permeability.

Global GHSZ Thicknesses

Burwicz et al (2011) have calculated GHSZ thicknesses based on the

global bathymetry, salinity, bottom water temperature, and heat flow (as a

proxy to geothermal gradients as they are not globally available).

GHSZ thicknesses can be considered a proxy for potential hydrate deposits

distribution but not necessarily for the real volume of hydrate-bearing

sediments. The formation of hydrates is mainly controlled by methane

supply either through the direct degradation of organic matter within the

GHSZ or through an upward flux of deeper biogenic and thermogenic

methane. Global estimates of methane fluxes from deep sediments are

poorly constrained.

Gas Hydrate Stability Zone

Methane

Hydrate in Permafrost Soils

Methane

Hydrate in Seafloor SedimentsThe most common type of gas hydrate is methane hydrate and

the conditions required for its stability can occur in marine sediments and in permafrost

soil. The phase diagrams redrawn from Kvenvolden and Lorenson (2001) show the physical

conditions (temperature and pressure) required for the stability of methane hydrate in the

marine environment (top) and the permafrost environment (bottom).

First, we discuss the marine setting. Salty oceanic water can be no colder than about ?

1.8°C before freezing. Assume that you are in a polar region, where the sea bottom

temperature is 0°C. Furthermore, assume that the average temperature increase is 3°C

per 100m sediment depth. The figure then shows that methane hydrate cannot be stable

at a water depth of 100m. But it may occur in a seafloor that is 400m below sea level.

When drilling at a water depth of 400m, you can expect or hope to find a 370m thick

hydrate layer. Beneath this depth the temperatures get too high for a formation of gas

hydrate, so that free gas and water is found. For a case of 1,000m water depth, the

hydrate layer will be 600m thick. Obviously, the thickness of the hydrate zone will depend

on the temperature gradient. In sediments that display a stronger increase in temperature,

which can be the case, for example, at active continental margins (4–6°C per 100m

depth), the hydrate zone will generally be thinner.

Next, we look at the permafrost setting, where temperature gradients are considerably

lower than in the ocean. Typically, the temperature can be expected to change by 1.3°C

per 100m within the permafrost zone, and with 2°C per 100m in layers below the

permafrost zone. The ambient temperature and the thickness of the frozen layer are

therefore of significant importance for the stability of gas hydrate.

Consider the case where the base of the permafrost is at a depth of 100m or less. The

figure shows that the physical conditions will not be adequate for the formation of gas

hydrate. If the permafrost base is, say, at 750m, the thickness of the gas hydrate zone is

900m.

Since the stability of gas hydrates is related to relatively low temperatures and high

pressure, any change in these two parameters can increase or decrease the stability of the

gas hydrate. For example, if either the temperature is increased or the pressure is

reduced, the gas hydrate will change phase from a solid to a gas and liquid.

Gas hydrates are not chemical compounds since the sequestered molecules are never

bonded to the lattice. The formation and decomposition of hydrates are first-order phase

transitions. However, the detailed formation and decomposition mechanisms are still not

well understood on a molecular level.

PART V: Gas Hydrates - The Resource Potential

Natural gas hydrate occurs worldwide: in oceanic sediments of continental

slopes; in deepwater sediments of inland lakes and seas; and in both

continental and continental shelf polar sediments. In oceanic sediments,

where water depths exceed about 300m and bottom water temperatures

approach 0°C, gas hydrate is found at the seafloor and down to sediment

depths of about 1,100m. The typical depth range for hydrate stability lies

100–500m beneath the seafloor. In polar continental regions, gas

hydrate can occur in sediments at depths ranging from 150 to 2,000m.

Occurrences of hydrates within the gas hydrate stability zone (GHSZ) are

affected by numerous additional factors, including availability of gas,

water, and geological controls. About 98% of the gas hydrates

are believed to be concentrated in oceanic sediments, while the other 2%

are in polar landmasses.

How Much Gas Hydrate Exists?

Gas hydrate resource pyramid: Gas hydrates exist in a variety of forms that pose different

opportunities and challenges for energy resource exploration and production. The left axis displays

lithology of the host sediment. The right axis shows associated estimates of natural gas resources.

Gas hydrate-bearing sands are the most feasible initial targets for energy recovery. Other

occurrences, such as gas hydrate-filled fractures in clay-dominated reservoirs, may become

potential energy production targets in the long-term future (Courtesy: Ray Boswell).Gas

volumes are often cited in units of trillion cubic feet (Tcf), and there

are approximately 35.3 cubic feet in a cubic metre. It is estimated that

resources of methane in natural hydrate reservoirs range anywhere from

105 to 2.8 x 106 Tcf, or around 2.8 x 1015 to 8 x 1015 m3, indicating that more

carbon is contained in methane hydrate than in all other organic carbon

reservoirs on earth combined.

These estimates, however, include hydrate in low-grade shale deposits

as well as in high-grade sand deposits. Only a fraction of the methane

sequestered in global gas hydrate deposits is likely to be both

concentrated and accessible enough to ever be considered a potential

target for energy resource exploitation.

The relative amounts of gas hydrate in the global system can be

illustrated by the hydrate resource pyramid, which captures the

distribution of sequestered methane among the major types of global gas

hydrate deposits. Only the hydrates at the top of the pyramid – a small

subset of the hydrate deposits – are likely to be considered viable as a

source of commercial quantities of natural gas.

Occurrences in Muds and Coarse Silt

At the top of the pyramid lie high permeability sediments in

permafrost areas. The amount of gas hydrate in these settings globally is

relatively small, but permafrost-associated gas hydrates might be the

easiest to commercialise, particularly in areas with well-developed

infrastructure from conventional hydrocarbon production, such as the

Alaskan North Slope.

Gas hydrate resources housed in marine sand reservoirs are also

obvious major targets for any longer-term development of gas hydrates as

a resource. Highly permeable marine sands with moderate to high gas

hydrate saturations are considered the best targets for resource

development. Recent logging-while-drilling in the Gulf of Mexico

has identified geologic units with inferred hydrate saturations as high as

80%.

Reservoir quality is expected to increase with increasing grain

size. However, the primary control of importance may be intrinsic

permeability. Sediments of high intrinsic permeability may have the

capability to host hydrate at high saturations (50–90% of pore space).

Occurrences in Muds and Fine Silt

Below marine sands in the gas hydrate resource pyramid is the category

for muds and fine silt. Fractured muds are less permeable, usually smaller-

grained sediments that may host gas hydrates in fracture-related

permeability. Drilling on the Indian and Korean margins and in the Gulf of

Mexico has found gas hydrate filling pervasive fractures within low

permeability sediments (e.g., silts and clays). Such sediments may not

have a high average saturation of gas hydrate, maybe around 20%,

but targeted production from gas hydrates within the fractures could

theoretically yield significant gas.

At the base of the resource pyramid lie gas hydrates in low

permeability, undeformed fine-grained muds. Such sediments host most of

the global gas in place in methane hydrates and are unlikely to become a

target for commercial production of gas from methane hydrates. The

saturation typically is only 5%.

Sea-floor mound deposits are small size and ephemeral. They

are environmentally sensitive due to associated unique biological

communities and thus unattractive as a resource target.

Potential Worldwide

Hydrate Energy International (HEI) recently released estimates of the gas hydrate resource

potential, utilising a petroleum systems approach (Source: Johnson, 2011).In conventional

petroleum systems analysis, the geological components and processes

necessary to generate and store hydrocarbons are well established:

source, migration, reservoir, seal, and timing. To apply this petroleum

system model to a methane hydrate resource system, one needs also to

incorporate the parameters that determine methane hydrate stability

conditions: formation temperature and pressure, pore water salinity, water

availability, gas source, gas transport, gas concentration, and the time

over which the system evolves.

Recently, Hydrate Energy International (HEI), as part of the Global Energy

Assessment being conducted by the International Institute for Applied

Systems Analysis (IIASA), released the results of a new evaluation of the

gas hydrate resource potential, utilising a petroleum systems approach.

Their median assessment is around 43,000 Tcf.

Geological Settings of Gas Hydrate

Gas hydrates occur in a wide variety of geologic settings and modes of

occurrence. These include gas hydrate concentration, host lithology,

distribution within the sediment matrix, burial depth, water depth, and

many others. The major controlling factor on where gas hydrate forms is

lithology and availability of methane.

The HOTSPOT IMAGE (below) from Boswell (2011) gives a schematic

depiction of the components of various methane hydrate systems.

Examples A and B represent massive forms in hydrate-bearing marine

clays. Example C shows a hydrate-bearing marine sand. Examples D and E

represent sea-floor mounds (outcrops) and hydrate-bearing clays (finely

dispersed).

Three dominant types of gas hydrate accumulations can be defined and

distinguished based on the mode of fluid migration and gas hydrate

concentration within the GHSZ (Milkov and Sassen, 2002). The end-

members are structural and stratigraphic accumulations, but combination

accumulations controlled both by structures and stratigraphy may occur.

+

-

C

A, B

D

E

F

HOTSPOT IMAGE: A schematic depiction of the components of various methane hydrate systems. 

Typical methane hydrate reservoir morphologies include (A) networks of hydrate-

filled veins; (B) massive hydrate lenses; (C) grain-filling methane hydrate in

marine sands; (D) massive sea-floor mounds; (E) grain-filling methane hydrate in

marine clays; (F) grain-filling methane hydrate in onshore

arctic sands/conglomerates (Click on map for photographic examples).

The general location of the most resource-relevant (blue circles) and

most climate-relevant (green circles) methane hydrate occurrences are

also shown. Other parts of the methane hydrate system as depicted include

the relationship between microbial and thermogenic gas sources and

gas migration controls.

SOURCE: R. Boswell, 2011.

Structural Accumulations

Structural gas hydrate accumulations occur in advective high fluid flux

settings, where highly permeable fractured conduits like fault systems,

mud volcanoes and other geological structures facilitate rapid

fluid transport from depth into the GHSZ. The gas hydrate concentration in

the sediments is relatively high. Gas hydrate deposits associated with

active faults and craters of deepwater mud volcanoes usually present high

gas hydrate concentrations, with 30–50% of the pore space filled by

hydrates.

The shallow seafloor consists typically of non-consolidated silts and clays.

Various types of gas hydrates may occur: layers of hydrates of

thicknesses from millimetres to tens of centimetres, massive hydrate

deposits, or hydrate outcrops (mounds) on the seafloor.

Bottom-simulating reflectors (BSRs) are not common in

structural accumulations as they do not typically seal much gas below the

gas hydrate layer. If present, they are patchy and displaced and they do

not parallel the seafloor.

Stratigraphic Accumulations

Stratigraphic gas hydrate accumulations generally occur in advective low

fluid flux settings within passive margins in relatively coarse-grained

sediments, from biogenic methane gas generated in situ, or gas which is

slowly supplied from deeper in the subsurface.

In stratigraphic accumulations, gas hydrate tends to be highly

dispersed through the GHSZ, and low hydrate concentrations are

commonly measured; 1–12% of the pore space is filled by hydrates. The

low hydrate concentration can be explained by the low permeability and

porosity in clay-rich sediments, which hinder the mobility of both water

and gas, necessary for hydrate formation. Most of the hydrate in clay-

dominated sediments is present in a network of tiny fractures. 

However, there are significant exceptions. Both the lithostatic

pressure (depth) and the sediment type influence how the gas hydrate will

occupy the sediment pore space. Deeper in the sediment column below

the seafloor, the hydrate cannot overcome the lithostatic pressure

between the sediment grains and must reside in the pore space or

in fractures. For coarse-grained sediments, such as sands, hydrates can

become highly saturated.

A well-known example is the Nankai Trough, where gas hydrate occupies

up to 82% of pores in thin but very permeable sand units. The Nankai

Trough is located beneath the Pacific Ocean off the south-east coast of

Japan, and is known as an active subduction and earthquake zone.

BSRs are commonly observed on the eastern Nankai margin. This is to

date the only place where a successful gas hydrate production test has

been performed.

Seismic attribute co-blend map (RMS amplitude/coherence) showing sand channels in excess of 150m thick. The

bright yellow and orange colours highlight zones with high seismic amplitudes characteristic of sand channels.

The displayed interval shows several generations of sand deposits within the gas hydrate stability zone. If

charged with gas they could form prospective targets for gas hydrate exploration. (Reichel and Gallagher, 2014)

Mapping of Gas Hydrate

Interpretation of seismic data provides the most important means for

mapping and characterising the distribution of gas hydrates and possible

underlying free gas. Shallow high-amplitude events can be generated by

features other than gas hydrate – for example, carbonate cemented zones,

layered clays, the bases of mass transport complexes, and unconformities.

However, the presence of seismic bottom-simulating reflectors is the most

common indicator of the presence of gas hydrate. The BSR is often a

strong, coherent reflector that lies at the base of the gas hydrate stability

zone and is overlain by sediments containing gas hydrate and underlain by

sediments containing free gas. The BSR has negative reflection amplitude

caused by the difference in elastic impedance. The base of the free-gas

zone is rarely evident in the seismic section and the concentration of free

gas is thought to decrease gradually downward to water-saturated

sediments. In rare cases we may observe a flat spot – in exceptional cases,

as in the illustration below, even two – beneath the BSR.

Seismic example of marine gas hydrates above a double flat spot. The contrast between the high-velocity hydrate-bearing strata and the low-velocity gasbearing strata beneath results in the bottomsimulating reflector (BSR).

In this example, the gas hydrates act as seals for underlying hydrocarbon reservoirs (Courtesy: Statoil, Sonangol E.P. and Schlumberger Multiclient)

Seismic feature enhancement of BSR and two underlying flat spots (Courtesy: Statoil, Sonangol E.P. and Schlumberger Multiclient).